Systems and methods for reducing pvt effects during pressure testing of a wellbore fluid containment system

ABSTRACT

A system for pressure testing a component of a well system includes a tubular member extending into a wellbore. The tubular member has a fluid passageway and one or more nodes that are configured to measure fluid pressure. The system also includes a heat exchanger configured to cool a fluid passing therethrough.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Disclosure

The disclosure relates generally to systems and methods for conducting apressure test of wellbore system equipment. More particularly, thedisclosure relates to systems and methods for mitigatingpressure-volume-temperature (PVT) effects that take place while pressuretesting wellbore fluid containment system equipment such as blowoutpreventers (BOPs), choke and kill lines, wellhead hangers, casing, linerand liner hangers, tubing hangers, completions and other equipment.

2. Background of the Technology

In drilling for oil and gas from a hydrocarbon producing well, a well orwell system is provided that includes a drilling rig with a risersection and a drill string used to convey drilling fluid down the drillstring and through a wellhead to a drill bit disposed within a wellboreof a formation. The fluid recirculates from the drill bit back to thedrilling rig via an annulus formed between the drill string and walls ofthe wellbore, and via the annulus formed between the drill string andthe riser section that encircles it. A wellbore or formation fluidinflux, also called a “kick”, can cause an unstable and unsafe conditionat the drilling rig. When a kick is detected, a fluid containment systemof the well system may be actuated and steps may be taken to “kill” thewell and regain control. The fluid containment system includes allcritical sealing points, including the BOP and its associated rams, thechoke and kill lines and their associated valves, the choke and killmanifolds, an internal BOP (IBOP).

Due to the criticality of the functional operation of the fluidcontainment system with regard to containing and managing fluidpressurizations within the well system, periodic testing of eachcomponent (e.g., BOP, choke and kill lines, etc.) and each sealingelement of the fluid containment system is important. Per current U.S.federal regulations, pressure testing of the fluid containment systemmust be conducted upon installation and before 14 days have elapsedsince the last BOP pressure test. For instance, each ram of the BOP andeach valve of the choke and kill lines must be individually pressuretested to properly comply with current regulations. Low and highpressure tests must be conducted for each individual component, and eachcomponent and sealing element must demonstrate that it holds areasonably stable pressure. For instance, in practice a pressure decayrate of 4 pounds per square inch (psi) per minute or less is seen asreasonably stable.

Even though a fluid containment system component need only demonstratepressure holding capability for five minutes to pass apresently-required pressure test, conducting the individual tests oftentake much longer due to PVT effects that take place due to thepressurizing of the test fluid. Specifically, for fluids (e.g., drillingfluid, completion fluid, etc.), an increase in pressure of the fluidwill result in an increase of temperature of the fluid, while a decreasein temperature of the fluid will correspondingly result in a decrease inpressure of the fluid. The temperature of the testing fluid increasesduring pressurization due to heat generated by friction during thepumping of the fluid by a cementing unit, mud pump, or either types ofhigh pressure pumps. For instance, heat generated by pistons of atriplex pump as they reciprocate may be transferred to the pressurizedtesting fluid. For this reason, testing fluid pumped into the fluidcontainment system may feature a larger temperature increase than fluidalready disposed in the system, which is pressurized by the injectioninto the system of the pumped-in testing fluid. Referring to FIG. 1,graph 200 illustrates fluid pressures in relation to time at differentpositions along a vertically-oriented subsea drill string during apressure test. Pressure curve 110 illustrates the fluid pressure at apoint within the drill string near the sea floor, with curves 130, 120and 110 illustrating fluid pressure at progressively shallower pointsalong the drill string, with curve 110 illustrating fluid pressure atthe shallowest point, near the surface of the water. Due to beinglocated at different vertical depths along the drill string, curve 110is at the highest pressure, while curve 140 is at the lowest pressure ofthe curves. As shown in FIG. 1, the pressure test can be divided intothree phases: a pumping phase (112, 122, 132 and 142), a shut-in phase(114, 124, 134 and 144) and a depressurization phase (116, 126, 136 and146). The pumping phase takes places when testing fluid is pumped intothe well system in order to pressurize the fluid containment system.Testing fluid may be pumped into the drill string by a cementing unit ormud pump disposed at the drilling rig. Once the well system has beenpressurized to the testing pressure, pumping ceases and the well systemis shut-in, such that a portion of the well system containing the systemcomponents to be tested is isolated from the outside environment.Shut-in phases 114, 124, 134 and 144 have a beginning (114 a, 124 a, 134a and 144 a) and an ending (114 b, 124 b, 134 b and 144 b). As shown byFIG. 1, the pressure at the beginning 114 a, 124 a, 134 a and 144 aexceeds the pressure at the end 114 b, 124 b, 134 b and 144 of theshut-in phase. Further, the difference in pressure between beginning 144a and ending 144 b is greater than the difference in pressures between114 a and 114 b, due to curve 140 being at a shallower point along thedrill string. Also, in this pressure test, shut-in phases include apressurization point (114 c, 124 c, 134 c and 144 c) where additionaltesting fluid is pumped into the well system to slightly increase thepressure within the system. Additional fluid may be pumped in during theshut-in phase to raise the pressure within the well system to a levelsimilar to that existing near the beginning of the tests, at points 114a, 124 a, 134 a and 144 a.

Referring to FIG. 2, graph 200 illustrates fluid temperatures inrelation to time at different positions along the vertically orientedsubsea drill string during a pressure test. Temperature curve 210 isgenerated by temperature sensors positioned at the same verticalposition along the drill string as the pressure sensors generatingpressure curve 110, curve 220 is generated by temperature sensorspositioned at the same position as curve 120, etc. Temperature curve240, at the shallowest position along the drill string, displays thegreatest downward slope of the curves 210, 220, 230 and 240. The greaterslope of temperature curve 240 is due to being in closer proximity tothe testing fluid that has been pumped into the well system for thepurpose of pressurization. For instance, heat from the testing fluidpumped into the well system during the pumping phase may transfer toproximal fluid at the position of temperature curve 240, resulting in agreater difference in temperature between testing fluid within the drillstring at the position of sensors generating curve 240 and ambient watersurrounding the drill string at that point, which cools the testingfluid within the drill string following pressurization. Referring toFIGS. 1 and 2, the greater decrease in temperature along curve 240provides for the greater decrease in pressure during shut-in phase 144of pressure curve 140. Specifically, the greater drop in temperature offluid of curve 240 results in more PVT effect driven pressure decayduring shut-in phase 144.

During the performance of the pressure test, an analog and lowresolution circular chart reader may be used by drilling personnel onthe drilling rig to observe a continuous pressure recording of the fluidcontainment system. Even in cases where the fluid containment systemcomponent being tested is not leaking, the pressure test often lastsover half an hour before the pressure within the fluid containmentsystem begins to stabilize enough such that a five minute period ofsuccessful pressure stabilization may be recorded. Further, due topressure decay caused by PVT effects and the low resolution of the chartrecorder, pressure tests are sometimes judged as successful before fullstabilization (e.g., decay of 4 psi/min or less, as is a typical currentstandard in certain jurisdictions), thus allowing for the risk that theremaining pressure decay may be due to a leak, in addition to PVTeffects. In practice, this phenomenon is especially impactful at highertesting pressures as are required in deeper wells and where syntheticoil based mud (SOBM) is used as the testing fluid.

Accordingly, there remains a need in the art for systems and methodsthat allow for quick and effective pressure testing of well systemequipment, such as a fluid containment system. Further, it would beadvantageous if such systems and methods would mitigate the PVT effectsthat take place during a pressure test of well system equipment. Stillfurther, it would be advantageous to provide a system that includes ameans providing a continuous pressure signal with a relatively highresolution.

BRIEF SUMMARY OF THE DISCLOSURE

Disclosed herein is a system for pressure testing a component of a wellsystem that includes a tubular member that extends into a wellborepenetrating a subterranean formation. The tubular member has a firstfluid passageway and one or more nodes that are configured to measurefluid pressure and are coupled to the tubular member. The system alsoincludes a heat exchanger having a second fluid passageway and isconfigured to cool a fluid passing through the second passageway.Further, the system includes a fluid flowpath that includes at least aportion of the first fluid passageway and at least a portion of thesecond fluid passageway. In an embodiment, the tubular member comprisesa drill string. In another embodiment, the tubular member comprises aproduction riser. In an embodiment, the system further includes a pumpin fluid communication with the fluid flowpath. In this embodiment, thepump is configured to pressurize the cooled fluid to produce apressurized fluid. The pressurized fluid has a temperature that issubstantially equal to the temperature of the first volume of fluid. Inan embodiment, the system further includes a test plug disposed withinthe tubular member.

Also disclosed herein is a method for pressure testing a component of awell system that includes producing a cooled fluid by cooling a firstvolume of fluid having a first pressure. The cooled fluid is flowed intoa closeable chamber of the well system and shut in to the chamber.Pressure in the chamber is measured using nodes distributed within thechamber. In an embodiment, flowing the cooled fluid into the chambercomprises pressurizing the cooled fluid to produce a pressurized fluidhaving a second pressure that is greater than the first pressure of thefirst volume of fluid. In an embodiment, pressurizing the cooled fluidto produce a pressurized fluid includes pressurizing the cooled fluid toa temperature that is substantially equal to the temperature of thefirst volume of fluid. In an embodiment, pressurizing the cooled fluidto produce a pressurized fluid includes pressurizing the cooled fluid toa temperature that is less than the temperature of the first volume offluid. In an embodiment, the method further includes determining thepresence of a leak within the closeable chamber by monitoring thepressure measurement. In an embodiment, cooling the fluid to produce thecooled fluid comprises flowing the first volume of fluid through a heatexchanger.

Embodiments described herein comprise a combination of features andcharacteristics intended to address various shortcomings associated withcertain prior devices, systems, and methods. The various features andcharacteristics described above, as well as others, will be readilyapparent to those skilled in the art upon reading the following detaileddescription, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the exemplary embodiments of the inventiondisclosed herein, reference will now be made to the accompanyingdrawings in which:

FIG. 1 is a graph illustrating pressure curves generated during apressure test of a drilling system;

FIG. 2 is a graph illustrating temperature curves generated during apressure test of a drilling system;

FIG. 3 is a schematic view of an embodiment of a drilling system inaccordance with principles described herein;

FIGS. 4A-4D are perspective views, some in cross-section, showingcomponents of the downhole electromagnetic network shown in FIG. 3;

FIG. 5 is a schematic view of a heat exchanger employed in the drillingsystem shown in FIG. 3;

FIG. 6 is a schematic of the testing fluid system shown in FIG. 3;

FIG. 7 is a schematic showing the drilling system shown in FIG. 3configured to conduct a fluid containment system pressure test;

FIG. 8A is a graph illustrating pressure curves generated during apressure test of the BOP pressure testing application shown in FIG. 7;

FIG. 8B is a graph illustrating temperature curves generated a pressuretest of the BOP pressure testing application shown in FIG. 7;

FIG. 9 is a schematic showing the drilling system shown in FIG. 3configured for conducting a pressure test of a completion system; and

FIG. 10 is a schematic of a production system configured for pressuretesting in accordance with principles described herein.

DETAILED DESCRIPTION

The following discussion is directed to various exemplary embodiments.However, one skilled in the art will understand that the examplesdisclosed herein have broad application, and that the discussion of anyembodiment is meant only to be exemplary of that embodiment, and notintended to suggest that the scope of the disclosure, including theclaims, is limited to that embodiment. The drawing figures are notnecessarily to scale. Certain features and components herein may beshown exaggerated in scale or in somewhat schematic form and somedetails of conventional elements may not be shown in interest of clarityand conciseness.

In the following discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to . . . .” Also, theterm “couple” or “couples” is intended to mean either an indirect ordirect connection. Thus, if a first device couples to a second device,that connection may be through a direct connection, or through anindirect connection via other devices, components, and connections. Inaddition, as used herein, the terms “axial” and “axially” generally meanalong or parallel to a given axis (e.g., given axis of a body or aport), while the terms “radial” and “radially” generally meanperpendicular to the given axis. For instance, an axial distance refersto a distance measured along or parallel to the given axis, and a radialdistance means a distance measured perpendicular to the given axis.Still further, as used herein, the phrase “communication coupler” refersto a device or structure that communicates a signal across therespective ends of two adjacent tubular members, such as the threadedbox/pin ends of adjacent pipe joints; and the phrase “wired drill pipe”or “WDP” refers to one or more tubular members, including drill pipe,drill collars, casing, tubing, subs, and other conduits, that areconfigured for use in a drill string and include a wired link. As usedherein, the phrase “wired link” refers to a pathway that is at leastpartially wired along or through a WDP joint for conducting signals, and“communication link” refers to a plurality of communicatively-connectedtubular members, such as interconnected WDP joints for conductingsignals over a distance.

A system and method for pressure testing a well system is disclosedherein. Embodiments described herein may be employed in various wellsystem applications; however, it has particular application as a systemand method for mitigating PVT effects during the pressure testing ofvarious elements of the fluid containment system, such as the BOPs,casing, Christmas tree, tubing hangers, etc. Further, it has particularapplication with regard to offshore well systems.

Referring now to FIG. 3, a well or drilling system 10 generally includesan offshore semi-submersible well system rig 20 at the water line 12having a testing fluid system 21 disposed thereon. In other embodiments,rig 20 may comprise other varying types of offshore platforms, such asdrilling ships, submerged platforms, etc. System 10 further includes amarine riser 30 that extends between the rig 20 and a wellhead 60disposed at the sea floor 14, a fluid containment system 40, a drillstring 50 disposed within riser 30 and having a central axis 55 and aninternal fluid passageway 50 a, and a casing 70 supported by cement 72.

An annulus 35 is formed between drill string 50 and riser 30 and allowsfor the recirculation of drilling fluid to rig 20 from a wellbore 62formed in the subterranean formation 16. A fluid containment systemcomprises several components configured to retain and manage pressurewithin drill string 50 and annulus 35. In the embodiment of drillingstring 10, fluid containment system 40 includes BOP 41, choke line 44,kill line 46 and an internal BOP (IBOP) 48. Rams 42 of BOP 41 areconfigured to provide an annular seal 43 upon actuation, dividingannulus 35 into an upper section 35 a extending between rig 20 and seal43 and a lower section 35 b extending from seal 43 downward into thewellbore 62. During drilling, a high pressure volume of fluid from theformation 16 may flow into wellbore 62 and travel upward through annulus35. This formation “kick” may be isolated within lower section 35 a ofannulus 35 via actuating one or more rams 42, providing the annular seal43. Choke line 44 and kill line 46 provide for alternate routes of fluidcommunication between rig 20 and the portion of annulus 35 disposedbelow BOP 41.

During a formation kick, high pressure fluid from the formation may becirculated upward through choke line 44 to the rig 20, in order toreduce the pressure of the formation fluid within the annulus 35. Chokeline 44 comprises a lower valve 44 a, a manifold 44 b and an upper valve44 c. Also, each valve (lower 44 a and upper 44 b) may include an innerand outer valve, with each valve being individually pressure tested.Fluid flow through choke line 44 may be restricted by closing lowervalve 44 a or upper valve 44 c. Further, choke manifold 44 b comprisesone or more valves and chokes and is configured to manage and regulateflow through choke line 44. Because successful control of a formationkick may depend on the effective operation of choke line 44 and itscomponents, valves 44 a, 44 c and manifold 44 b are pressure testedduring the pressure testing of fluid containment system 40. Kill line 46is also used to manage a formation kick by allowing for circulationbetween annulus 35 and rig 20. Kill line 46 is used to pump high densitydrilling mud or other fluid downward from rig 20 to the annulus 35 tocirculate the formation influx out of the wellbore 62. Thus, a kill linesuch as kill line 46 may be used to “kill” the well by stopping or atleast substantially restricting the flow of fluid from the formationinto the wellbore 62 by pumping heavy fluid into annulus 35 from the rig20. Kill line 46 comprises a lower valve 46 a, a kill manifold 46 b andan upper valve 46 c. As with choke line 44, flow through kill line 46may be substantially restricted or controlled via valves 46 a, 46 c andmanifold 46 b. Thus, during pressure testing of fluid containment system40, valves 46 a, 46 c and manifold 46 b are pressure tested as well.

IBOP 48 is disposed at an upper end 50 b of drill string 50 at the rig20 and is configured to manage fluid pressure within drill string 50.For instance, during a formation kick, high pressure formation fluid maybegin flowing upward through string 50 via an opening or port of thestring 50 disposed within wellbore 62. IBOP 48 may restrict the flow offluid out of drill string 50 at upper end 50 b. Thus, because IBOP 48may be used in effectively controlling a formation kick, IBOP 48 ispressure tested during the pressure testing of fluid containment system40.

Referring now to FIGS. 3, 4A-4D, drill string 50 comprises a pluralityof nodes 51 having sensors 57 coupled between a plurality of pipe joints52. Wired or networked drill pipe incorporating distributed sensors cantransmit data from anywhere along the drill string 50 to the rig 20 foranalysis. Nodes 51 are provided at desired intervals along the drillstring 50. Network nodes 51 essentially function as signal repeaters toregenerate and/or boost data signals and mitigate signal attenuation asdata is transmitted up and down the drill string. The nodes 51 may alsoinclude measurement assemblies. The nodes 51 may be integrated into anexisting section of drill string or a downhole tool along the drillstring 50. For purposes of this disclosure, the term “sensors” isunderstood to comprise sources (to emit/transmit energy/signals),receivers (to receive/detect energy/signals), and transducers (tooperate as either source/receiver). Pipe joints 52 include a first pipeend 53 having, for example, a first induction coil 53 a and a secondpipe end 54 having, for example, a second induction coil 54 a.

Nodes 51 comprise a portion of a downhole electromagnetic network 56that provides an electromagnetic signal path that is used to transmitinformation along the drill string 50. The downhole network 56, orbroadband network telemetry, may thus include multiple nodes 51 basedalong the drill string 50. Communication links 52 a may be used toconnect the nodes 51 to one another, and may comprise cables or othertransmission media integrated directly into sections of the drill string50. The cable may be routed through the central borehole of the drillstring 50, or routed externally to the drill string 50, or mountedwithin a groove, slot or passageway in the drill string 50. Preferablysignals from the plurality of sensors along the drill string 50 aretransmitted to a remote location (e.g., rig 20) through a wire conductor52 a along the drill string 50. Communication links 52 a between thenodes 51 may also use wireless connections. A plurality of packets maybe used to transmit information along the nodes 51. Further detail withrespect to suitable nodes, a network, and data packets are disclosed inU.S. Pat. No. 7,207,396 (Hall et al., 2007), hereby incorporated in itsentirety by reference.

Various types of sensors 57 may be employed along the drill string 50 invarious embodiments, including without limitation, axially spacedpressure sensors, temperature sensors, and others. The sensors 57 may bedisposed on the nodes 51 positioned along the drill string, disposed ontools incorporated into the string of drill string, or a combinationthereof. The downhole network 56 transmits information from each of aplurality of sensors 57 to a surface computer 58. In some embodiments,the sensors 57 are annular pressure sensors.

Rig 20 includes a well site computer 58 that may display information forthe drilling operator. Information may also be transmitted from computer58 to another computer 59, located at a site remote from the well, withthis computer 59 allowing an individual in the office remote from thewell to review the data output by the sensors 57. Although only a fewsensors 57 are shown in the figures, those skilled in the art willunderstand that a larger number of sensors may be disposed along a drillstring when drilling, and that all sensors associated with anyparticular node may be housed within or annexed to the node 51, so thata variety of sensors rather than a single sensor will be associated withthat particular node.

Due to safety concerns and to minimize the impact of a wellbore influx,it is important to detect and contain the influx as soon as possible. Insome circumstances, the BOPs are actuated and isolate the well at theonset of a formation influx. In some cases, for example in deepwaterwells, the wellbore influx may migrate above the BOP 41 at the time theBOP's rams are closed. In the embodiments herein, downhole distributedmeasurements and the high speed broadband telemetry system allowwellsite personnel to identify potential remedial actions for themigrated wellbore influx. In some embodiments, the measurements used areindependent from surface measurements.

Referring again to FIG. 3, booster assemblies and network nodes 51 aredisposed along the drill string 50. In some embodiments, the boosterassemblies are spaced at 1,500 ft. (500 m) intervals to boost the datasignal as it travels the length of the drill string 50 to prevent signaldegradation. Network nodes 51 are also located at these intervals toallow measurements to be taken along the length of the drill string 50.The distributed network nodes 51 provide measurements that give thedriller additional insight into what is happening along the potentiallymiles-long stretch of the drill string 50.

Well system rig 20 comprises a rig floor 22, a derrick 24 extending fromthe floor 22. Testing system 21 is disposed at rig floor 22 andcomprises a mud pit 25, one or more heat exchangers 26 a, 26 b, acementing unit 27 and a fluid conduit 28. Conduit 28 provides a fluidflowpath for a testing fluid 29 from mud pit 25, through heat exchangers26 a, 26 b and cementing unit 27 to the passageway 50 a of drill string50. Testing fluid 29 comprises a high density and high weight fluid(e.g., drilling fluid, SOBM, completion fluid, etc.) relative to ambientwater 13 disposed below water line 12. For instance, fluid 29 has arelatively higher density than fluid from formation 16.

Referring to FIG. 5, a schematic of heat exchanger 26 a is shown. In theexample shown in FIGS. 3, heat exchangers 26 a, 26 b are shell and tubeheat exchangers having a tube side fluid passageway 26 c and a shellside fluid passageway 26 d with two tube sheets 26 e that create a sealbetween tube side 26 c and shell side 26 d. Testing fluid 29 entersshell side passageway 26 c via port 26 f, flows through a plurality oftubes 26 g, and exits via port 26 i. Also, heat exchanger 26 b issubstantially identical to heat exchanger 26 a in structure.

Chilled water 26 i enters tube side 26 d via port 26 j, follows adeviated flowpath around internal baffles 26 k, and exits via port 26 l.While water 26 i flows through shell side 26 d, water 26 i contacts theouter surfaces of the plurality of tubes 26 g, allowing for heat totransfer out of the testing fluid 29 disposed within tubes 26 g and intothe chilled water 26 i. Thus, due to this heat transfer between testingfluid 29 and water 26 i, the testing fluid 29 entering port 26 f is at ahigher temperature than the testing fluid 29 exiting port 26 fh, and thechilled water 26 i entering port 26 j is at a lower temperature than thewater 26 i exiting port 26 l. The amount of temperature drop betweentesting fluid 29 entering port 26 f and testing fluid 29 exiting port 26h is a function of the temperature of the chilled water 26 i as itenters port 26 j, the mass flow rate of water 26 i, and the mass flowrate of the testing fluid 29. For instance, increasing the mass flowrate of chilled water 26 i entering heat exchanger 26 a will increasethe temperature drop of the testing fluid 29 as it flows through theheat exchanger. Also, increasing the mass flow rate of the testing fluid29 will decrease the temperature drop in the fluid 29 as it passesthrough heat exchanger 26 a.

In the embodiment illustrated in FIG. 5, chilled water 26 i enters port26 j at approximately 35° F. and exits port 26 l at approximately 39° F.Testing fluid 29 enters port 26 f at approximately 90° F. and exits port26 h at approximately 68° F., forming a cool fluid. In otherembodiments, chilled water 26 i may enter port 26 j at othertemperatures, and testing fluid 29 may enter port 26 f at othertemperatures. Further, in other embodiments, water 26 i may compriseother fluids suitable for transferring heat out of testing fluid 29 asthe two fluids flow through heat exchanger 26 a. In other embodiments,heat exchangers 26 a. 26 b may be another style of heat exchanger, suchas a plate, a plate and fin, a phase change, an air coil and other typesof heat exchangers.

Referring now to FIG. 6, a schematic of testing fluid system 21 isshown. In this embodiment of testing fluid system 21, a first volume oftesting fluid flows from mud pit 21 through heat exchanger 26 a tocementing unit 27. Testing fluid 29 may be circulated to mud pit 25 fromwellbore 62 via riser 30 (FIG. 3). Testing fluid 29 has a temperature T₁as it flows from mud pit 25 to heat exchanger 26 a. Fluid 29 at thispoint has yet to be pressurized and thus temperature T₁ is at an ambientlevel with respect to the surrounding environment. A cooled fluid isformed via passing testing fluid 29 through heat exchanger 26 a, coolingfluid 29 to a temperature T₂, which is cooler than the temperature T₁.In this example, T₁ is approximately 90° F. while T₂ is approximately68° F. After passing through heat exchanger 26 a, testing fluid 29enters cementing unit 27. Cementing unit 27 comprises a high pressurepump suitable for forming a pressurized fluid via pressurizing testfluid 29 from ambient pressure to pressures ranging from 5,000-12,000pounds per square inch (psi). In this embodiment, cementing unit 27comprises a triplex reciprocating pump that pressurizes fluid 29 betweenapproximately 8,000-12,000 psi. Due to PVT effects, the pressurizationof fluid 29 by unit 27 increases the temperature of fluid 29 fromtemperature T₂ to a higher temperature T₃. In this embodiment, thepumping action of cementing unit 27 increases the temperature of thetesting fluid 29 by approximately 22° F., and thus temperature T₃ isapproximately 90° F. or ambient with respect to the surrounding airtemperature. Also, the pressurized testing fluid at temperature T₃ isapproximately equal in temperature as the first volume of fluid attemperature T₁. Thus, the configuration of heat exchanger 26 a andcementing unit 27 results in a pressurized testing fluid 29 atapproximately 10,000 psi at an ambient temperature T₃ of 90° F.

Referring still to FIG. 6, in an embodiment, second heat exchanger 26 bis provided downstream of cementing unit 27. As test fluid 29 passesthrough heat exchanger 26 b, it decreases in temperature fromtemperature T₃ to a temperature T₄ of approximately 75° F. Heatexchanger 26 b is configured to lower the temperature of the test fluid29 to a temperature that is substantially equal to the ambient water 13surrounding riser 30 (FIG. 3) at shallow depths. For instance, astesting fluid 29 is pumped into drill string 50, a portion of testingfluid 29 will be disposed within a segment of the drill string 50 thatis below the water line 12. Because the temperature of the ambient watermay 13 be cooler than the ambient air temperature, testing fluid 29disposed below the water line 12 may be cooled to below ambient airtemperature (e.g., cooled to 80° F.) in order to eliminate anysubstantial difference in the temperatures of the testing fluid 29 andthe surrounding ambient water 13 below water line 12. Each temperatureT₆-T_(n), is measured at a corresponding depth from the water line 12.T₆ is measured at depth 13 a, T₇ is measured at depth 13 b and T_(n) ismeasured at depth 13 n, where the depth of 13 n is greater than thedepth of 13 a, 13 b and 13 c. Because the temperature of water 13disposed at depth 13 b is greater than the temperature of the water at13 a, the temperature of fluid 29 disposed at depth 13 a is cooled to agreater extent than the fluid 29 disposed at depth 13 b, etc. The amountof heat transferred out of fluid 29, as fluid 29 flows through heatexchangers 26 a and 26 b, is controlled via the pump rate of cementingunit 27, the temperature of water 26 i as it enters heat exchangers 26 aand 26 b, and the flow rate of water 26 i (FIG. 5) as it enters heatexchangers 26 a and 26 b.

While the testing fluid system 21 is shown in FIG. 6 as having two heatexchangers (26 a and 26 b), in other embodiments the testing fluidsystem of a well system may only have one heat exchanger disposedbetween a mud pit (e.g., mud pit 25) and a cementing unit (e.g.,cementing unit 27). In that arrangement, the temperature of the testingfluid after pressurization by the cementing unit is substantially equalto the temperature of the fluid before it enters the heat exchanger.Thus, the temperature of testing fluid 29 entering drillstring 50 issubstantially equal to the ambient air temperature. In otherembodiments, two or more heat exchangers may be included in the testingfluid, depending on the amount of cooling required to have substantiallyequal temperatures between the first volume of testing fluid enteringthe first heat exchanger and the pressurized testing fluid entering thedrill string.

Referring now to FIG. 7, drilling system 10 previously described withreference to FIG. 3, is shown configured for pressure testing fluidcontainment system 40. As shown, drill string 50 comprises a BOP testplug 49 that is coupled to an end of two adjacent pipe joints 52 and isdisposed axially below BOP 41, proximal to wellhead 60. As shown in FIG.7, test plug 49 is configured to prevent fluid within drill string 50from flowing across plug 49. Test plug 49 also forms an annular seal 49a, preventing fluid flow within annulus 35 across test plug 49. A radialport or opening 45 is provided in the drillstring 50 to act as a routeof fluid communication between drillstring 50 and the annulus 35 axiallyabove testing plug 49. A ram 42 of BOP 41 may be actuated to form anannular seal, preventing fluid passing through port 45 from flowingupward through annulus 35 to the rig 20. Thus, annular seals 49 a and 43form a closable annular chamber 35 c within riser 30. Pressure andtemperature is continuously measured at different locations of annulus35 is detected via nodes 51. For instance, pressure and temperature offluid within chamber 35 c is continuously measured via node 51 a. Themeasurements taken by sensors 57 of nodes 51 are continuouslytransmitted to rig 20 via electromagnetic downhole network 56.

In the example of FIG. 7, fluid containment system 40 is filled withhigh density testing fluid 29 (e.g., mud, water based drilling fluid,SOBM, completion brine, etc.) at a relatively low pressure. Pressurewithin drillstring 50 and annular chamber 35 c of annulus 35 isincreased to the required BOP testing pressure by injecting a volume oftesting fluid 29 into drillstring 50. Testing fluid 29 is pumped viacementing unit 27 into drill string 50 via fluid flowpath 29 a thatcomprises mud pit 25, passageway 26 c of heat exchanger 26 a, cementingunit 27, passageway 26 c of heat exchanger 26 b and passageway 50 a ofstring 50. Before entering cementing unit 27, testing fluid 29 passesthrough the tube side of heat exchanger 26 a (FIG. 5), chilling thetesting fluid 29 to a temperature below the ambient air temperature atthe rig 20. Testing fluid 29 is pressurized to approximately between5,000-12,000 psi, increasing the temperature of testing fluid 29 to atemperature substantially equal to the ambient air temperature at rig20. Following pressurization by cementing unit 27, testing fluid 29flows through heat exchanger 26 b, lowering the temperature of testingfluid 29 to a temperature substantially equal to the ambient water 13temperature surrounding riser 30. A volume of testing fluid 29 is thendisplaced into drill string 50, pressurizing fluid within drill string50 and the annular chamber 35 c. In subsequent pressure tests of otherelements of the fluid containment system 40, testing fluid 29 is alsodisposed within choke line 44 and kill line 46.

Referring now to FIGS. 8A and 8B, graphs of pressure and temperature oftesting fluid 29 measured during the BOP pressure test of FIG. 7 areshown. Pressure graph 500 illustrates pressure curve 510 as measured byand transmitted from node 51 a during the BOP pressure test illustratedin FIG. 7. As shown in FIG. 8A, pressure curve 510 comprises a pumpingphase 512, a shut-in phase 514 having a beginning 514 a and an end 514,and a depressurization phase 516. During pumping phase 512, testingfluid 29 is pumped into drillstring 50 via cementing unit 27, which inturn displaces a volume of fluid into chamber 35 c, pressurizing thechamber 35 c to the BOP testing pressure. Once pressure within chamber35 c has reached the BOP testing pressure, the beginning 514 a ofshut-in phase 514 takes place with the cessation of pumping fromcementing unit 27, thus stopping the flow of testing fluid 29 intodrillstring 50 at rig 20. As part of a BOP pressure test shown in FIG.7, ram 42 must successfully hold the BOP test pressure for a specifiedperiod of time. In one example, ram 42 must hold 15,000 psi for a periodof five minutes. Because the testing fluid 29 that is now disposedwithin drillstring 50 has been chilled via heat exchangers 26 a and 26b, shut-in phase 514 of pressure curve 510 is stable with respect totime, varying to a lesser degree over time than the pressure curvesshown in FIG. 1 where the testing fluid is not compensated for thetemperature increase caused by heat being transferred into the fluid viathe pressurization performed by a cementing unit or other pump type.Thus, shut-in phase 514 may have a relatively shorter duration than theshut-in phases shown in FIG. 1, as the requirement of holding the BOPtest pressure (e.g., 10,000 psi) within chamber 35 c for a specifiedamount of time (e.g., five minutes) will be satisfied more quickly dueto the stability and continuity of the shut-in phase 514 of pressurecurve 510 provided by mitigating and/or eliminating heat transfer out ofthe fluid following the pumping phase, allowing for a faster BOPpressure test.

Pressure within drillstring 50 and chamber 35 c exhibits a stableshut-in phase 514 due to the testing fluid 29 having a stabletemperature following pumping phase 512. For instance, referring to FIG.8B, a temperature curve 610 of the temperature of fluid proximal to node51 a (FIG. 7) within chamber 35 c is shown during the shut-in phase ofthe BOP pressure test. Temperature curve 610 exhibits a stable and nearconstant slope, thus eliminating or at least substantially reducing PVTrelated effects on the testing fluid 29 for the duration of the shut-inphase 514. Thus, any substantial fluctuation of pressure during shut-inphase 514 may be properly attributed to a leak within the fluidcontainment system 40, such as a leak within annular seal 43 provided byram 42, rather than being caused by a decrease in temperature of testingfluid 29.

Referring back to FIG. 7, in addition to 7 ram 42 of BOP 41 beingpressure tested, other components of fluid containment system 40 may bepressure tested in a similar manner. For instance, other individual ramsof BOP 41 may be actuated to create an annular seal within annulus 35,forming a cavity defined by the ram's annular seal and the seal 49 aproduced by BOP test plug 49. Likewise, (inner and outer) lower valves44 a, 46 a, manifolds 44 b, 46 b, and upper (inner and outer) valves 44c, 46 c, of choke line 44 and kill line 46, respectively, may bepressure tested by placing nodes (e.g., nodes similar to nodes 51)within choke line 44 or kill line 46 in order to continuously measureand transmit pressure and temperature readings from lines 44, 46. Inorder to test the components of choke line 44 and kill line 46, highdensity testing fluid 29 is pumped through heat exchangers 26 a and 26b, and into drillstring 50 via cementing unit 27. Ram 42 of BOP 41 maybe actuated to create annular seal 43. However, instead of allowingfluid communication between choke line 44 and kill line 46 with chamber35 c, a component of lines 44, 46, may be sealed (e.g., lower valve 44a). In this embodiment, the sealed component (e.g., valve 44 a) may bepressure tested to see if it holds the BOP test pressure for a requisiteperiod of time (e.g., five minutes).

Referring now to FIG. 9, drilling system 10 previously described withreference to FIG. 3 is shown configured for pressure testing wellcompletion system 80. Well completion system 80 generally includeswellhead 60, tubing hanger 82, tubing 84, casing 70 and cement 72. Inthis example, drillstring 50 has a lower terminal end 50 c that couplesto tubing hanger 82. Tubing hanger 82, disposed within wellhead 60,seals annulus 35 of riser 30 via annular seal 84 a. Tubing 84 couples totubing hanger 82 at terminal end 84 a, and extends downward intowellbore 62. Tubing 84 is configured to act as a route of fluidcommunication between formation 16 and a production riser (not shown)that is installed following completion. Tubing hanger 82 physicallysupports tubing 80 and allows for a route of fluid communication betweentubing 80 and drillstring 50. Further, annular seal 84 a of hanger 82prevents fluid within wellbore 62 from flowing upward and out ofwellbore 62 via annulus 35. Casing 70 allows for selective fluidcommunication between wellbore 62 and formation 16. For instance,following the completion pressure tests, casing 70 is perforated atpredetermined locations in wellbore 62 to provide routes of fluidcommunication with the formation 16 via the perforations.

Prior to installing the production system, well completion system 80 ispressure tested in order to ensure that completion 80 will not leak oncefluid from formation 16 begins to flow into wellbore 62 and tubing 84once production of hydrocarbons from formation 16 has commenced. As partof the pressure test, a radial port or opening 86 is provided withintubing 84 to allow for a route of fluid communication between tubing 84and wellbore 62. Prior to the initiation of the completion pressuretest, drillstring 50, tubing 80 and wellbore 62 are filled with highdensity testing fluid 29 (e.g., mud, SOBM, completion brine, etc.) at arelatively low pressure. Once filled, an additional volume of testingfluid 29 is pumped into drillstring 50 via conduit 28 and cementing unit27. Testing fluid 29 is pumped from mud pit 25 where it is stored atambient pressure and temperature (e.g., 90° F. and atmosphericpressure).

Testing fluid 29 passes through heat exchanger 26 a prior topressurization by cementing unit 27, and flows through a second heatexchanger 26 b prior to entering string 650. Thus, testing fluid 29 ischilled to below the ambient air temperature to a temperature ofapproximately 68° F. prior to pressurization via cementing unit 27,which increases the pressure of fluid 29 from 5,000-12,000 psi, in thisexample. Due to PVT effects (e.g., friction from pumping),pressurization of fluid 29 results in a temperature increase of thepressurized fluid such that fluid 29 returns to ambient temperature(e.g., the temperature of the testing fluid 29 as it exits mud pit 25).Before entering drillstring 50, fluid 29 passes through heat exchanger26 b, reducing the temperature of fluid 29 to below the ambient airtemperature to a temperature of approximately 80° F., in this example.Thus, the temperature of fluid 29 as it enters string 650 issubstantially equal to the temperature of the water 13.

Although the temperature of the water 13 proximal to rig 20 may vary bydepth, because only a relatively small volume of fluid 29 is pumped intodrillstring 50, the pressurized fluid 29 may be reduced to a temperatureheat exchanger 26 b to a temperature substantially equal to thetemperature of the water 13 at shallower depths (e.g., 0-500 feet belowwater line 12). Further, the pump rate of cementing unit 27 and the flowrate of chilled water 26 g (FIG. 5) may be varied to vary thetemperature of fluid 29 as it enters drillstring 50. The temperature offluid 29 may be varied to match the temperature of the water 13 at thedepth below water line 12 where that portion of fluid 29 will bedisposed following the completion of pumping. For instance, a firstportion of fluid 29 pumped into drillstring 50 may be cooled to agreater extent than a later portion of fluid 29, because the firstportion will occupy a lower depth in drillstring 50, which is surroundedby relatively cooler water 13, while the later portion will occupy ashallower depth within drillstring 50, which is surrounded by relativelywarmer water 13. Thus, by ensuring a relatively small temperaturedifference between the pumped in fluid 29, and the ambient water 13disposed proximal to that fluid 29, heat transfer from between theambient water 13 and the pumped in fluid 29 may be minimized.

Referring still to FIG. 9, as testing fluid 29 is pumped intodrillstring 50, fluid within drillstring 50 is displaced out of opening86 and into wellbore 62, pressurizing wellbore 62. Once wellbore 62 hasreached a completion test pressure (e.g., 12,000 psi), pumping viacementing unit 27 is stopped and the completion pressure test enters ashut-in phase. During the shut-in phase of the pressure test, continuouspressure measurements may be taken and transmitted to rig 20 via nodes51 and electromagnetic network 56. Sensors 57 of Nodes 51 continuouslymeasure pressure within annulus 35 of riser 30 and within drillstring50.

Referring now to FIG. 10, a well or production system 600 is shown.Production system 600 generally comprises rig 20, a production riser 630having a central axis 635 and ends 630 a and 630 b, a Christmas tree 410having an upper end 410 a and a lower end 410 b, and well completionsystem 80. Production riser 630 extends from upper end 630 a at rig 20to lower end 630 b that is coupled to the first end 410 a of Christmastree 410. The second end 610 b of Christmas tree 410 couples to wellhead60. Fluid communication between fluid within formation 16 and productionriser 630 is provided by tubing 84 disposed within wellbore 602.Production riser includes one or more nodes 51, which partly formelectromagnetic network 56. Christmas tree 410 generally includes anassembly of valves, spools and other fittings.

During and/or at the onset of the production phase, the various sealingelements and components of Christmas tree 410 are pressure tested inorder to ensure that production system 600 may contain a high pressureinflux of fluid from formation 16. In this example, testing fluid 29 maybe pressurized and injected into production riser 630 via testing fluidcircuit 21 disposed at the rig 20. Christmas tree 410 may be isolatedfrom the formation 16 via displacing a testing plug downward throughproduction riser 630 such that the plug is disposed within wellhead 60,sealing tubing 84 from tree 410 and riser 630. Testing fluid 29 is thenpumped into production riser 630, and a pressure test of Christmas tree410 is conducted. This pressure test may be iterated for everyindividual sealing element and component of Christmas tree 410 (e.g.,repeated for every valve, spool, etc.). Due to the cooling provided byheat exchangers 26 a and 26 b, the temperature of the testing fluid 29entering production riser 630 is substantially equal to or below thetemperature of the testing fluid 29 exiting mud pit 25 (e.g., ambientair temperature at 90° F.). Thus, the time required for pressure testingof Christmas tree 410 is reduced, as the transfer of heat out ofpressurized testing fluid 29 into the surrounding ambient water 13 iseliminated or at least substantially minimized.

While embodiments have been shown and described, modifications thereofcan be made by one skilled in the art without departing from the scopeor teachings herein. The embodiments described herein are exemplary onlyand are not limiting. Many variations and modifications of the systems,apparatus, and processes described herein are possible and are withinthe scope of the invention. Accordingly, the scope of protection is notlimited to the embodiments described herein, but is only limited by theclaims that follow, the scope of which shall include all equivalents ofthe subject matter of the claims. Unless expressly stated otherwise, thesteps in a method claim may be performed in any order. The recitation ofidentifiers such as (a), (b), (c) or (1), (2), (3) before steps in amethod claim are not intended to and do not specify a particular orderto the steps, but rather are used to simplify subsequent reference tosuch steps.

What is claimed is:
 1. A system for pressure testing a component of awell system comprising: a wellbore penetrating a subterranean formation;a tubular member extending into the wellbore having a first fluidpassageway; one or more nodes that are configured to measure fluidpressure and are coupled to the tubular member; a heat exchanger havinga second fluid passageway and is configured to cool a fluid passingthrough the second fluid passageway; and a fluid flowpath that comprisesat least a portion of the first fluid passageway and at least a portionof the second fluid passageway.
 2. The system of claim 1, wherein thetubular member comprises a drillstring.
 3. The system of claim 1,wherein the tubular member comprises a production riser.
 4. The systemof claim 1, wherein the heat exchanger is a shell and tube heatexchanger.
 5. The system of claim 1, further comprising a first volumeof fluid in the fluid flowpath having a first pressure.
 6. The system ofclaim 1, wherein the fluid flowpath further comprises an annulussurrounding the tubular member.
 7. The system of claim 1, wherein thefluid flowpath further comprises the wellbore of the system.
 8. Thesystem of claim 5, further comprising a pump in fluid communication withthe fluid flowpath and configured to pressurize fluid in the fluidflowpath to produce a pressurized fluid having a second pressure that isgreater than the first pressure of the first of fluid.
 9. The system ofclaim 8, wherein the temperature of the first volume of fluid issubstantially equal to the temperature of the pressurized fluid.
 10. Thesystem of claim 8, wherein the temperature of the pressurized fluid isless than the temperature of the first volume of fluid.
 11. The systemof claim 1, further comprising: a test plug disposed within the tubularmember; a ram of a blowout preventer disposed at least partially withinthe tubular member; and a sealed chamber formed by the tubular member,the ram and the test plug; wherein one of the one or more nodes isdisposed within the sealed chamber.
 12. The system of claim 8, whereinthe pressurized fluid comprises a first portion and a second portion,and wherein the first portion of the pressurized fluid is cooled to afirst temperature and the second portion of the pressurized fluid iscooled to a second temperature.
 13. The system of claim 12, wherein thefirst temperature is different than the second temperature.
 14. A methodfor pressure testing a well system comprising: cooling a first volume offluid having a first pressure to produce a cooled fluid; flowing thecooled fluid into a closeable chamber of the well system; shutting inthe chamber; and measuring a pressure in the chamber using nodesdistributed within the chamber.
 15. The method of claim 14, whereinflowing the cooled fluid into the chamber comprises pressurizing thecooled fluid to produce a pressurized fluid having a second pressurethat is greater than the first pressure of the first volume of fluid.16. The method of claim 14, transmitting the pressure measurement to aremote location.
 17. The method of claim 15, wherein pressurizing thecooled fluid to produce a pressurized fluid comprises pressurizing thecooled fluid to a temperature that is substantially equal to thetemperature of the first volume of fluid.
 18. The method of claim 15,wherein pressurizing the cooled fluid to produce a pressurized fluidcomprises pressurizing the cooled fluid to a temperature that is lessthan the temperature of the first volume of fluid.
 19. The method ofclaim 14, further comprising determining the presence of a leak withinthe closeable chamber by monitoring the pressure measurement.
 20. Themethod of claim 14, further comprising filling the closeable chamberwith the cooled fluid.
 21. The method of claim 14 further comprisingtransmitting the measured pressure to a remote location.
 22. The methodof claim 14 wherein the measured pressure is transmitted via a networkcomprising wired drill pipe.
 23. The method of claim 14, wherein coolingthe fluid to produce the cooled fluid comprises flowing the fluidthrough a heat exchanger.
 24. The method of claim 14, wherein thecloseable chamber comprises an annulus surrounding a tubular body. 25.The method of claim 14, wherein the closeable chamber comprises awellbore.
 26. The method of claim 14, wherein cooling the fluid toproduce a cooled fluid comprises cooling a first portion of the fluid toproduce a first cooled portion of fluid and cooling a second portion ofthe fluid to produce a second cooled portion of fluid.
 27. The method ofclaim 26, wherein the first cooled portion of fluid is cooled to atemperature that is higher than the temperature of the second cooledportion of fluid.
 28. The method of claim 14, wherein: flowing thecooled fluid into the chamber comprises pressurizing the cooled fluid toproduce a pressurized fluid; wherein cooling the fluid to produce acooled fluid comprises cooling a first portion of the fluid to a firsttemperature and cooling a second portion of the fluid to a secondtemperature that is different than the first temperature.